A number of oil and gas wellbore operations are implemented using a tubing string inserted in the wellbore. In some cases, the tubing string may include tools activated by a ball conveyed to the tool from the surface. These ball-activated tools typically include a ball seat on which the ball can land to create a seal so that pressure can be increased above the ball to actuate the tool.
A tubing string may use a number of these ball-activated tools in series. For example, well treatment strings for staged well treatment operations such as hydraulic fracturing often include a series of ball-activated sliding sleeves that can be individually activated to stimulate isolated portions of a wellbore. In these ball-activated systems, each sliding sleeve valve defines a ball seat designed to seat a ball of particular size, but allow smaller balls to pass through the seat. The ball seat diameters are graduated such that the ball seat closest to the surface has the largest diameter and the ball seat furthest down the well has the smallest diameter.
To activate a selected ball-activated sliding sleeve valve in such systems, the operator launches a ball having the appropriate size to seat at the selected valve. The ball passes through ball seats above the selected valve, but seats at the selected valve because the ball is too large to pass through the selected valve's ball seat. The operator can then increase pressure above the seated ball to actuate the selected valve. The operator continues to launch balls of progressively larger size and increase pressure in the string to actuate the sliding sleeve valves up the string. While these ball-activated sliding sleeve valve systems provide some significant benefits over prior systems, there are also some limitations in these systems.
Furthermore, the number of ball-activated stages that can be used within a tubing string in series is limited by the need to size the balls and ball seats appropriately. Indeed, as a practical matter, manufacturing tolerances of the balls and ball seats require that each ball/ball seat be of a sufficiently different size from others in the string to ensure that the wrong ball cannot seat in a ball seat. Moreover, as ball seat diameter decreases the flow restriction through the ball seat increases. Eventually, the flow restriction becomes so large that it becomes impractical to include additional ball-activated tools. These design and manufacturing considerations effectively limit the number of ball-activated tools that can be used in series for a given diameter tube string.
Furthermore, since a ball will block a portion of a tubing string inner bore after it is used to actuate a sliding sleeve valve, the continued presence of the ball may adversely affect subsequent operations such as shifting previously opened sleeves and back flowing production fluids. In certain circumstances the balls can be flowed back to the surface by flowing fluids up the well. However, the lifting forces of the fluid may be inadequate to carry the balls to surface. For this reason, among others, operators may be required to mill the balls in order to remove them from the tubing string. In addition, the operators may also be required to mill out the ball seats to remove the flow restrictions caused by the seats. Milling out items within a tubing string can be time consuming and costly.
Plugs that can be retrieved by retrieval tools rather than back flowing or milling have been proposed. These plugs suffer their own limitations however. Some conventional tool retrievable plugs are set using a setting line. Thus, the plugs must be run in tethered to a wireline, slickline or other setting line.
Moreover, after the plug is set, debris or other materials, for example proppant, may accumulate on top of the plug, which may make it difficult or even impossible to latch onto the plug for retrieval. The debris or other materials may also accumulate in the annular region between the plug and casing and may interfere with release of the plug.
One result of stimulation is that the return fluids (e.g., stimulation fluid, production fluid, etc.) may include proppant and other debris. It may be desirable in certain circumstances to screen the return fluid to prevent the proppant and other debris from flowing back into the tubing string. In some conventional systems, this involves providing a second set of “production ports” along the tubing string that are screened so that the return fluids can enter the tubing string through the screened ports and not the stimulation ports through which the stimulation fluid was injected into the formation.
These conventional systems suffer a number of limitations. As one disadvantage, these systems typically require the use of relatively complex tubing string components that include mechanisms to keep the screened ports fully closed during stimulation—otherwise, the proppant in the stimulation fluids would damage the screens due to the relatively high pressures used during stimulation—but allow the screened ports to be opened and the stimulation ports to be closed after stimulation. As another disadvantage, components providing both stimulation ports and screened ports must be relatively long to accommodate the extra set of ports.